Thursday, March 12, 2020

Reservoir Saturation

Reservoir saturation is derived from C/O or inferred from sigma measurements. Inelastic gamma ray spectra are used to determine the relative concentration of carbon and oxygen in the formation. A high C/O indicates oil-bearing formations; a low ratio indicates water-bearing formations. Sigma is derived from the rate of capture of thermal neutrons - mainly by chlorine - and is measured using capture gamma rays. Saline water has a high value of sigma, and fresh water and hydrocarbon have low values of sigma. 

As long as formation water salinity is high, constant and know, water saturation Sw may then be calculated.

Carbon-oxygen - Carbon-oxygen ratio is measured in two ways. A ratio (C/O yields) is obtained from full spectral analysis of carbon and oxygen elemental yields. A second C/O (C/O windows) is obtained by placing broad windows over the carbon and oxygen spectral peak regions of the inelastic spectrum.  

The C/O yields is the more accurate of the two ratios, but lower count rates and, therefore, poorer statistics make it less precise than the C/O windows. Conversely, C/O windows is often less accurate but has better statistics and so is more precise. Each ratio is first transformed to give an oil volume, and then the two oil volumes are combined using an alpha processing method to give a final oil volume with good accuracy and good precision. The transforms of C/O ratio to volume of oil use an extensive data base covering multiple combinations of lithology, porosity , hole size, casing size and weight, as well as a correction for the carbon density of the hydrocarbon phase. 


Wednesday, March 11, 2020

Pulsed Neutron Cased-Hole Logging

Advanced neutron generator design and fast, efficient gamma ray detectors combine to make a reservoir saturation tool that is capable of detailed formation evaluation through casing and more. Lithology determination, reservoir saturations and flow profiles are some of the comprehensive answers provided by this multipurpose tool.

 To manage existing fields as effectively and efficiently as possible, reservoir engineers monitor movement of formation fluids within the reservoir as well as production from individual wells. Pressure measurements play a vital role in reservoir management. However,these data need to be augmented by other measurements to detect fluid movement within the producing well and the surrounding formation. One recently introduced cased-hole logging tool, the RST Reservoir Saturation Tool, provides abundant single-well data to help reservoir engineers locate bypassed oil and detect waterflood fronts, fine-tune formation evaluation and monitor production profiles. 

A Multipurpose Service

The RST service was introduced in June, 1992 with a through-tubing pulsed neutron tool capable of providing both carbon-oxygen ratio (C/O) and sigma reservoir saturation measurements, under suitable formation and borehole condition, provide quantitative oil saturation. The high-yield neutron generator and high-efficiency dual-detector system provide higher gamma ray count rates, and hence better statistics, than previous generations of pulsed neutron devices. 

This has led to the development of many other applications, including spectroscopy  measurements, accurate time-lapse reservoir monitoring and evaluation in difficult logging environments such as variable formation water resistivity and complex lithology. 

Other features of the tool design allow several auxiliary measurements such as borehole salinity and thermal neutron porosity. The tool comes in two diameters- the 1 11/16- in. RST-A tool and 2 1/2 in. RST B tool. Both use the same type of neutron generator, detectors and electronics. 

However, the larger diameter RST-B tool incorporates shielding to focus the near detector towards the borehole and the far detector towards the borehole and the far detector towards the formation, allowing logging in flowing and unknown borehole fluids and also providing a borehole holdup measurement. More recent applications for the RST-A tool include WFL Water Flow Log measurements and separate oil and water phase velocities in horizontal wells- Phase Velocity Log (PVL) measurements. 

Essentially the RST service provides three types of measurements:
  • reservoir saturation from C/O or sigma measurements
  • Lithology and elemental yields from analysis of inelastic and capture gamma ray spectra
  • borehole fluid dynamics from holdup, WFL and PVL measurements.

Monday, March 9, 2020

Circulation : Mud Conditioning

Primary cementing operations often have multiple objectives. On long intermediate casing strings, a complete cement sheath from bottom to top is preferred, but a good seal near the bottom of the string and around the casing seat is all that may be required, making the casing seat the primary and the full cement sheath the secondary objectives. For liners, isolation away from the shoe (bottom) may be important as well as a seal at the liner-casing overlap. Cementing goals dictate job designs. To solve cementing problems, better understanding and application of fluid flow, displacements and placement are required along with careful design of mud systems, spacer fluids and cement slurries. Cement placement is important in most cases; mud removal is critical on all cementing jobs.

The accepted procedure is to circulate and condition before cement jobs. However, in the past, there were few guidelines for these procedures, except generally to reduce mud viscosity, gel strength and fluid loss; maximize standoff - casing centralization; use preflushes- chemical washes and spacers to separate mud and cement; move the pipe - rotate or reciprocate; circulate a minimum of two hole volumes and pump at high rates. Also, until a few years ago, critical flow-rate correction to account for casing eccentricity is significant and must be taken into consideration. 

Gelled mud must be removed from the annulus before placing cement, but mud in the narrow side of an eccentric annulus is often difficult to move. Casing standoff from borehole wallls is less than 100% even in vertical wells, and frequently no higher than 85%. At low flow rates, drilling mud with high yield stress and gel strength can be static in the narow gap of an eccentric annulus because of distorted velocities, lower frictional pressure drops and uneven wall shear stress distribution. This is undesirable because stationary mud may gel or dehydrate by static filtration at permeable zones and be difficult to mobilize during mud removal and cement placement. 

In the absence of pipe movement, frictional pressure drop and density differences are the only forces to move mud. Mud yield strength must be less than the wall shear stress generated by frictional pressure drop from viscous forces for mud to flow in narrow gaps. Wall shear stress can be increased by higher flow rates, improved standoff and increasing density differences, or mud gel strength can be reduced before casing is run. 



Sunday, March 8, 2020

Turbidite Deposits

Turbidite deposits are produced by turbidite flows. The hallmark of this sediment has been described simply by Bouma (1962), known as the Bouma Sequence. Turbidite deposition usually occurs in submarine fans. Walker (1978) divides turbidite deposition models into four facies associations, those are channel feeder, upper fan, middle fan, and lower fan. 



Wednesday, February 12, 2020

Seamless Fluids Prgrams: A Key to Better Well Construction

New insights into displacement mechanics inside casing and in the annulus, combined with integrated drilling and cementing fluid services, can improve primary cementing. This structured "fluids-train" approach also optimizes overal drilling and completion performance at lower cost for operators. 

Improvements in well construction are possible if long standing boundaries between drilling and cementing can be eliminated, and if mud removal and displacement criteria are properly applied. Efficient slurry placement for complete and permanent zonal isolation relies on effective displacement of drilling fluids from the casing-borehole annulus - mud removal - and on avoiding bypassing, mixing and contamination of fluids in the annulus and casing during cement placement. 

Understanding displacement mechanics is essential to successful cementing, but an integrated drilling and cementing fluids approach is a first step toward overall wellbore optimization.

The consequences of poor primary cementing jobs can be severe. Incomplete mud removal may leave channels, allowing communication between subsurface zones or to the surface. Likewise, failure to properly separate fluids as they are pumped downhole can negate the most meticulous plans or the best designs and lead to ineffective mud removaal or contamination that prevents cement from ever setting up (hardening). Approaching well construction as a series of interrelated events in which both mud and cement play important roles - total fluid management- results in a more controllable, structured process with optimal wellbores as the objective. 

Traditionally, drilling fluids and cementing services have been provided separately and the lack of stated, common objectives has been a roadblock to optimizing these operations. Better management of fluid services requires drillers and cementers to work together from well start to finish to select muds that achieve drilling goals, but do not impede cementing success. Consideration must be given to providing gauge holes that allow casing centralization. It may be necesary to reduce rates of penetration - average to high instead of very high- during drilling if that means improved borehole conditions, lower-cost primary cement jobs and reduction or elimination of expensive repair workovers. 

Necessary elements are available and, in most cases, in place to do this; where efforts often fall short is in coordination and management of the entire process to realize maximum benefits. Success in terms of the final product- a safe, long-lasting wellbore at the lowest possible cost - should be an incentive to rethink and restate fluid objectives.

Better understanding of annular displacement is a key element that is already in place. By using physical and computer modeling, cementing criteria have improved. Simulation and design software allow the myriad of fluid factors and complicated interactions involved in primary cementing to be addressed qualitatively, and most of the time quantitatively as well. The total process ( mud removal and cement placement) including conditioning, annular flow regimes, spacer- a buffer between drilling muds and cement slurries- selection and fluid displacement inside pipe can now be evaluated in planning and design stages, during mud maintenance and conditioning, and before or after jobs.

High flow rates effectively displace mud if turbulent flow is achieved around the entire annulus, but are viable only if casing and hole sizes are relatively small and casing standoff from the borehole is adequate.  

Lower flow rates can also successfully remove mud in many cases where higher flow rates are not practical, but more sophisticated designs and modified fluids are often needed to achieve laminar displacements. 

Spacers with controllable properties - ability to suspend weighting agents, reasonable turbulent rates, adjustable rheology, compatibility, low fluid loss and a wide range of applications - are needed to meet and better apply mud removal criteria.

Finally, to close the fluid loop, displacements inside pipe must be understood because density differences may cause mixing of fluids or bypassing of mud by spacers, spacers by cement slurries or lead by tail slurries. Better understanding and application of fluid flow and displacement mechanics are required along with more careful  design of mud systems, spacer fluids and cement slurries to avoid common cementing problems. 





 The Case for Total Fluids Management

In the past, drilling and cementing fluids were often provided under individual service contracts, often by different companies. All to frequently, the attitude seemed to be, "drill as fast as possible and worry about cementing after reaching TD." Other needs and intentions, and deleterious effects that occur when some fluids commingle were often ignored. In principle, instead of segregating drilling and cementing fluid services, operations can be unified in a single, integrated process. Isolated service-line mentalities are replaced by a common goal of providing seamless fluids programs. Territorial considerations are forgotten , and the two disciplines work together to maximize the efficiency and effectiveness of all well-construction fluids.

Good communications and coordination are a necessity. Cementing designs are performed before drilling is complete, so choices about flow regime- turbulent or laminar - and spacer properties are made assuming hole size and mud characteristics. Last minute changes or unexpected variations in borehole conditions place cementers at a disadvantage. Irregular holes and washouts hinder mud removal and casing centralization, and may preclude use of preferred turbulent flow. Low standoffs result in large radial variations in annular fluid velocity around casing with higher velocity on the wide side and lower velocity on the narrow side. This leads to inefficient annular displacement and potentially poor cement bonds or channels. For cement jobs, casing OD to hole diameter ratio is close to unity, so annular flow can be calculated using a basic slot model.

Drilling fluid designs also influence cement job quality. For example, zonal isolation cannot be achieved unless mud and cuttings are removed from the annulus.  Drilling fluids must be designed, maintained and treated to provide optimum final hole conditions, and ultimately be conditioned before cementing for easy removal by spacers and cement. Ideal muds for efficient displacement are nonthixotropic and have reduced gel strenths, plastic viscosities and yield points; low density to facilitate removal by buoyant forces; minimal fluid loss to prevent thick filter cakes and differential sticking; and are chemically compatible with cements. Perfect muds, however, cannot be achieved in practice, so efforts must be made to get close to ideal characteristics during selection, maintenance and precementing circulation.

Drilling fluid density and rheology must be kept low to meet mud-removal requirements. Displacing fluid weights and viscosities become higher with each successive interface, which can lead to unacceptably high cement densities and viscosities, and possible lost circulation if initial mud weight is too high. Just circulating and conditioning mud before cementing is not enough; effective solids and chemical control of rheology are required throughout drilling operations. If drilling fluids are not properly designed or deteriorate during drilling or logging, gelled mud that is difficult to remove may be left in washouts or on the narrow side of the annulus

Fluids compatibility also impacts annular displacement. Fluid mixtures should have lower rheologies than the individual fluids, but because this is difficult to achieve for muds and spacers, designs need to minimize mixture viscosities. 

Problems also arise if cement and mud mix inside or outside casing. Some drilling fluid additives accelerate or retard cement thickening times. But more commonly, cement-mud combinations result in high-viscosity mixtures and corresponding friction pressure increases that lead to excessive surface pump pressures and premature job termination as well as inefficient displacement. Washers and spacers isolate these potentially incompatible fluids , but unexpected variations in composition leave cementers unprepared to maintain this separation. This can be avoided using bottom wiper plugs to separate fluids inside casing and liners.


In addition to displacement considerations, cementing cost is an issue as hole sizes increase from washout or enlargement. The cost of larger cement volumes is obvious, but additional centralizer cost to achieve adequate standoff for effective mud removal is often overlooked.

Some elements of drilling fluids performance were acceptable, but hole geometries that cementers had to address were not. Bentonite mud was not conducive to drilling gauge holes and a PHPA fluid failed to prevent washouts that were responsible for major cementing cost over-runs. Enlarged holes were compensated for by pumping extra cement, knowing that there was risk of channeling due to reduced fluid velocities in washouts.  

Unconsolidated formations in these wells were identified as the cause of washouts, so because of the lack of success with even a moderately inhibitive PHPA system, mixed-metal-hydroxide (MMH) mud with unique fluid rheology was chosen to minimize hole enlargement. 

After the revised fluids program was implemented, gauge holes allowed for better casing centralization and improved displacement designs- a laminar flow regime was chosen for these wellbore geometries. Spacers effectively removed MMH fluids from the annulus and logs indicated good cement placement and successful zonal isolation.  








 




 





Sunday, February 9, 2020

The Roots of Gas Migration

Of the two principal objectives facing primary cementing operations- casing support and zonal isolation- the latter usually raises the most concern, and is perhaps the hardest to achieve when there is potential for formation gas to migrate into the cement sheath. The challenge for industry is to achieve a long-term annular cement seal and prevent formation gas entry. Successful handling of gas migration is an evolving science. 

Gas invasion occurs when pressure is lower in the annulus than at the formation face. Gas then migrates either to a lower pressure formation or to the surface. The severity of the problem may range from residual gas pressure of a few psi at the wellhead to a blowout. Whatever the severity, the major factors contributing to gas migration are common. 

Successfully achieving a long-term annular cement seal begins by understanding these contributing factors  and knowing what can be done to minimize or counteract their effects. 

In the past, various techniques have been developed to tackle individual factors that contribute to gas migration. However, gas migration is caused by numerous related factors. Only by addressing each factor systematically can a reasonable degree of success be expected. 

Successfully cementing a well that has potential for gas migration involves a wide range of parameters: fluid density, mud removal strategy, cement slurry design (including fluid-loss control and slurry free water), cement hydration processes, cement-casing-formation bonding and set cement mechanical properties. 

Although gas may enter the annulus by a number of distinct mechanisms, the prerequisites for gas entry are similar. There must be a driving force to initiate the flow of gas, and space within the cemented annulus for the gas to occupy. The driving force comes when pressure in the annulus adjacent to a gas zone falls below the formation gas pressure. Space for the gas to occupy may be within the cement medium or adjacent to it.

To understand how, and under what circumstances, gas entry occurs, a review of the main mechanisms, including cement hydration and resultant pressure decline, follows. First, however, no cementing article is complete without emphasizing that good cementing practices are vital. To effectively cement gas-bearing formations the central pillars of good practice- density control, mud removal and slurry design are critical.



Density: Controlling the driving force- gas can invade and migrate within the cement sheath only if formation pressuree is higher than hydrostatic pressure at the borehole wall. Therefore, as a primary requirement, slurry density must be correctly designed to prevent gas flow during cement placement. However, there is a danger of losing circulation or fracturing an interval if fluid densities are too high. Also, consideration must be given to the free-fall or U-tubing phenomenon that occurs during cement jobs. Therefore, cement jobs should be designed using a placement computer simulator program to assure that the pressure at critical zones remains between the pore and fracture pressures during and immediately after the cement job.

Any density errors made while mixing a slurry on surface may induce large changes in critical slurry properties, such as rheology and setting time. Inconsistent mixing also results in placement of a nonuniform column of cement in the annulus that may lead to soilds settling, free-water development or premature bridging in some parts of the annulus. This is why modern, process-controlled mixing systems that offer accurate density control are proving popular for critical cement operations.

A cement slurry will not transmit hydrostatic pressure forever. The transition from a liquid that controls formation pressure to an impermeable solid is not instantaneous. Consequently, there is a period during which cement loses the ability to transmit pressure. No matter how carefully a slurry has been designed to counterbalance formation pressure, it will not necessarily resist gas invasion throughout the hydration process.



Mud removal : No easy paths for gas - If channels of mud remain in the annulus, the lower yield stresses of drilling fluids may offer a preferential route for gas migration. Furthermore, water may be drawn from the mud channels when they come into contact with cement. This can lead to shrinkage-induced cracking of the mud, which also provides a route gas to flow. 

If the mud filter cake dehydrates after the cement sets, an annulus may form at the formation-cement interface, thus providing another path for gas to migrate. 

How Gas Gets into the Annulus


Understanding the mechanisms of gas migration is complicated by the evolution of the annular cement column with time. The slurry begins as a dense, granular suspension that fully transmits hydrostatic pressure. As the slurry gels, a two-phase material comprised of a solid network with pore fluid forms. Finally , the setting process reaches a point where the cement is for all intents and purposes an impermeable solid. After slurry placement, gas may enter through different mechanisms according to the evolution of the cement's state, the pressures it experiences and other wellbore factors.


Cement state 1: Dense granular fluid

When pumping stops, the cement slurry in the annulus is a dense, granular fluid that transmits full hydrostatic pressure. If formation pore pressure is not greater than this hydrostatic pressure, gas cannot invade. However, almost immediately, pressure within the annulus begins to fall because of a combination of gelation, fluid loss and bulk shrinkage. 

This pressure reduction is best described by the evolution of a wall shear stress (WSS) that begins to support the annular column as the cement slurry gels. In order for a stress to evolve to counteract the hydrostatic pressure, there must be a vertical or axial strain at the annulus walls. This strain is caused by the removal of material during the hydration and setting processes - primarily through fluid loss and shrinkage.

As the cement sets, static gel strength constantly increases, with the rate of increase dependent on the nature of the slurry. There is potential for gas invasion once pressure in the annulus falls below the pressure in the gas-bearing formation. Even with a mud filter cake between the formation and cement, a differential pressure of less than 1 psi may allow gas to invade. The resistance of an external filter cake to gas flow is controlled by the cake's strength and adhesion to the rock face, which both have relatively low values for drilling fluids and neat cements.

This explains the driving force of gas invasion, however, there must also be space within the cemented annulus for gas to occupy. Space is provided by shrinkage, which occurs because the volume of the hydrated phase is generally less than that of the initial reactants.  

Permeability is more complicated issue. Once gelation begins, a cement slurry can be considered as a pseudoporous medium as long as the stress that it must withstand from formation fluid is less than its intrinsic strength. Thus, even though only a partial structure has been formed and the cement column is not yet fully self-supporting, with regard to its flow capacities, it can be said to have permeability. 

Cement slurries display an evolving yield stress that must be overcome before gas entry and flow can occur. Depending on the state of the slurry, gas can migrate by micropercolation, bubbles or fractures. Opportunity for gas entry decreases as the cement cures. 

Cement state 2: A two-phase material

Once a cement column becomes fully self-supporting, it may be considered to act as a matrix of interconnected solid particles containing a fluid phase. Setting continues and hydration accelerates. Pressure, now a pore pressure, decreases further as cement hydration consumes mix water. This leads to an absolute volume reduction or shrinkage of the internal cement matrix by up to 6%. Furthermore, the majority of shrinkage occurs at this stage, leading to tangential tensile stresses in the annulus, which may assist the initiation of fractures and disrupt bonding between the cement and the casing of formation.

Internal shrinkage creates a secondary porosity in the cement composed mainly of conductive pores. At the same time, the volume of water continuously decreases due to hydration, and its ability to move within the pores is reduced by chemical and capillary forces. Shrinkage and water reduction sharply decrease the hydrostatic pressure that cement exerts on formations.

There are two essentially different mechanisms for gas invasion at this stage, depending on the strength of the solid structure and the ease with which pore fluid can be forced through the cement pores by invading gas.

Early in the setting process, while the cement still has a weak soild structure, the possibility of creating fingers or viscoelastic fractures remains. Later, the solid network becomes sufficiently stiff and strong to withstand this effect, and gas invasion and subsequent flow are limited by the impermeability of the solid network to pore fluids. 

Once gas has invaded the porous structure of the cement, it may rise due to buoyancy forces. Alternatively, if the invading gas remains connected through the cement pore space to the gas-bearing formation, the higher pressure in the formation may force gas farther into the annulus. If gas pressure is higher than the minimum compressive stress in the cement and the permeability is too low to allow significant flow, then the cement may fracture. However, this is likely to occur only where residual tensile stresses in the annulus are sufficiently high to allow cracks to open under the influence of the gas pressure.

During the latter stages of this phase, there is a significant and rapid decrease in pore pressure as water is further consumed by hydration. If this occurs while the pore structure is still interconnected, gas may invade and flow rapidly through this pore space. Gas flow may also displace fluid remaining in the pores and prevent complete hydration that would eventually block pore spaces with reaction products.

Cement state 3: An elastic solid

Once hydration is complete, cement becomes an elastic and brittle material that is isotropic, homogeneous and essentially impermeable. In most cases, gas can no longer migrate within the cement matrix and can flow only through interfacial channels or where there has been mechanical failure of the cement.

Regardless of the cement system used, gas can still migrate at the cement-formation or cement-casing interfaces if a microannulus develops, or along paths of weakness where the bond strength is reduced. Both shear and hydraulic bond strengths vary as a function of the same external parameters. Bond strengths increase with effective mud removal, and ith water-wet rather than oil-wet surfaces.

Long-term cement durability is important if a well is to remain safe throughout its life-time. During its active life, a cemented annulus may be subjected to wide variations of temperature and stress from pressure testing, workover operations and variations in producing conditions.

However, field surveys on gas storage wells- which endure some of the most extreme swings in conditions - determined that annular gas leakage occurs early, within the first few cyclic fluctuations in temperature and pressure, rather than over a long period. 






























Resistivity While Drilling- Images from the String

Resistivity measurements made while drilling are maturing to match the quality and diversity of their wireline counterparts. Recent advances include the development of multiple depth-of-investigation resistivity tools for examining invasion profiles, and button electrode tools capable of producing borehole images as the drillstring turns.

It is hard to believe that logging while drilling (LWD) has come such a long way over the last decade. In the early 1980s, LWD measurements were restricted to simple resistivity curves and gamma ray logs, used more for correlation than formation evaluation. Gradually, sophisticated resistivity, density and neutron porosity tools have been added to the LWD arsenal. With the advent of high-deviation, horizontal and now slim multilateral wells, LWD measurements often provide the only means of evaluating reservoirs. The quality and diversity of LWD tools have continued to develop quickly to meet this demand. Today, applications include not only petrophysical analysis, but also geosteering and geological interpretation from LWD imaging. This article focuses on the latest LWD resistivity tools- the RAB Resistivity-at-the-Bit tool and the ARC5 Array Resistivity Compensated tool - and the images they provide.


Geology From the Bit

Simply stated, resistivity tools fall into two categories: laterolog tools that are suitable for logging in conductive muds, highly resistivity formations and resistive invasion; and induction tools which work best in highly conductive formations and can operate in conductive or nonconductive muds. The RAB tool falls into the first category although, strictly speaking, it is an electrode resistivity tool of which laterologs are one type. 

The RAB tool has four main features: 
  • toroidal transmitters that generate axial current- a technique highly suited to LWD resistivity tools.
  • cylindrical focusing that compensates for charateristic overshoots in resistivity readings at bed boundaries allowing accurate true resistivity Rt determination and excellent axial resolution
  • bit resistivity that provides the earliest indication of reservoir penetration or arrival at a casing or coring point - also known for geostopping
  • azimuthal electrodes that produce a borehole image during rotary drilling. 
This last feature allows the RAB tool to be used for geological interpretation. 

Three 1-in. [2.54-cm] diameter buttons are mounted along the axis on one side of the RAB tool. Each button monitors radial current flow into the formation. As the drillstring turns, these buttons scan the borehole wall, producing 56 resistivity measurements per rotation from each button. The data are processed and stored downhole for later retrieval when the RAB tool is returned to the surface during a bit change. Once downloaded to the wellsite workstation, images can be produced and interpreted using standard geological applications like  StrucView Geoframe structural cross section software. 

Wellsite images allow geologists to quickly confirm the structural position of the well during drilling, permitting any necessary directional changes. Fracture identification helps optimize well direction for maximum production.